All combined cycle steam plants have rapid-closing stop valves in steam lines to protect the turbine. The rapid valve closure produces a steam hammer in the piping resulting in large forces for which the piping system and supporting structures need to be designed. These forces are typically calculated using the classical Method Of Characteristics (MOC) solution. An evaluation has been conducted which compares the forces computed using the classical methods with a best-estimate approach. This comparison has been done to define margin, and to benchmark and identify potential refinements in the techniques used for evaluating steam hammer loads. The best-estimate approach involves the use of the RELAP5 computer program. RELAP5 is used extensively in the Nuclear Industry to evaluate fast thermal hydraulic transients. It has the capability to analyze subcooled liquid, two-phase and saturated or superheated steam piping system. The models used in RELAP5 are best estimate results in comparison to the MOC solution which are mathematically derived from theory. The compressible flow program GAFT is used to obtain the MOC solution. The main steam line of a single Heat Recovery Steam Generator combined cycle plant is modeled with both the GAFT program and with a PC version of RELAP5. Identical piping lengths, mass flow rates, pressures are used in each model. Also, a stop valve closure time of 100 milliseconds is modeled. As RELAP5 output results are pressure, flow rate, velocity, and density, the resultant forces are generated using the R5FORCE program, a post-processor to compute associated transient forces on straight piping links. The GAFT program, which is specifically designed to compute steam hammer forces, computes the force history internally on straight piping lengths. A comparison of the peak force from GAFT and from RELAP for every piping link has been generated. Through the comparison, both RELAP5 and GAFT have been verified for the evaluation of rapid valve closure reaction loads. The comparison also shows that the classical method typically over-predicts the best-estimate solution by 15% to 20% for straight piping links. Although not confirmed, a better agreement between the two methods would be expected if a more accurate steam sonic velocity correlation and valve closure model are incorporated into the classical solution. Theis study helps to quantify the degree of conservatism inherent in the classical approach.

In the year 2000 one of Europe’s most flexible power stations was commissioned by the authors’ company. The existing fossil fired power station was modified by a “Parallel Repowering”. With that concept three gas turbines (GT) in combination with three heat recovery steam generators (HRSG) were tied-in additionally to the fired boiler. This concept is compelling especially for large steam power plants and offers more flexibility than “Full Repowering” in matching GTs with the existing steam turbine (ST). The key to maintaining reliability of the repowered unit is the ST modernisation. Plant operability enhancements provide the flexibility of the fired boiler and ST for load following and peaking purposes. The authors’ company was responsible for the complete conversion of the fossil fired power station into a modern combined cycle unit. This comprises the tie-in of new steam pipes, bypass stations and the upgrade of the steam turbine auxiliaries as well as the implementation of a new automation system parallel to the existing one. The “Parallel Repowering” offers a maximum of operation variations: •Conventional (Rakine cycle) mode. •Open cycle mode (only GT). •Combined cycle mode. •Hybrid mode. The non-OEM steam turbine needed to be modified for the combined cycle operation with GTs. The condenser load had to be kept as low as possible because of the existing condenser design. Auxiliary systems like the gland steam system and the drain system had to be modified for all different operating modes. Special design features, like the IP rotor cooling system and the flange heating system, had to be extended to operate under all circumstances. One essential difference to the existing operational mode is the necessity of a steam bypass operation. Existing cold reheat (CRH) piping is of carbon steel, so the ST needs to be started with an isolated HP cylinder. The following modifications for the HP turbine were necessary: •For the isolated HP cylinder operation non-return valves (NRV) were built into the CRH line at the HP turbine exhaust. •The HP cylinder will be automatically isolated by closure of the HP valves and the non-return valves in the CRH line, and the simultaneous opening of the HP vent line. •As no instrumentation was available for a reliable monitoring of the isolated operation, a controlled reverse flow from the CRH to the HP vent line was established. •The HP cylinder evacuation is controlled by a dedicated control logic.

This paper presents an assessment of heat injection as a means of improving natural draft cooling tower performance. The concept involves injecting heat into the cooling tower exit air/vapor stream immediately above the drift eliminators in order to increase the difference between the density of the exit air/vapor stream and the ambient air. The density difference between the air/vapor in the cooling tower stack and the ambient air is the engine that drives airflow through the cooling tower. The enhancement of the airflow through the cooling tower (the natural draft) results in more evaporation and thus lowers the circulating water temperature. Because the heat is injected above the drift eliminators, it does not heat the circulating water. To evaluate the cooling tower performance improvement as a function of heat injection rate, a thermal/aerodynamic computer model of Entergy’s White Bluff 1 & 2 and Independence 1 & 2 (approximately 840 MW each) natural draft cooling towers was developed. The computer model demonstrated that very substantial reductions in cold water temperature (up to 7°F) are obtainable by the injection of heat. This paper also discusses a number of possible heat sources. Sources of heat covered include extraction steam, auxiliary steam, boiler blow-down, and waste heat from a combustion turbine. The latter source of heat would create a combined cycle unit with the combination taking place in the condensing part of the cycle (bottom of the cycle) instead of the steam portion of the cycle (top of the cycle).

In this study, in order to obtain fundamental data for designing the practical gas turbine combustors in the chemical gas turbine (Ch/GT) combined cycle system and/or other gas turbine systems which utilize low heating value fuel such as coal and biomass gasification syngas, we have simulated low heating value fuel–air turbulent diffusion combustion. The simulated results for the profiles of temperature and species concentrations have been compared with the measured ones. As a reaction model, the flamelet model has been applied to predict the turbulent diffusion combustion characteristics. A flamelet library which indicates relationships for scalar dissipation rate, mixture fraction, and mass fraction of chemical species were given by the calculated results of counterflow diffusion flame using 16 chemical species and 25 elementary reactions. Clipped Gaussian and a log-normal distribution were employed as the PDFs of the mixture fraction and the scalar dissipation rate, respectively. In this model, the k -ε two equations turbulence model is used to describe the turbulent flow field and the radiative heat transfer is calculated by the six-flux model. The governing equations were solved iteratively by the SIMPLE algorithm. By the comparisons of the simulated and measured results, it was clarified that the simulated profiles conformed fairly well to the measured ones in the turbulent combustor, and that this combustion simulation model could predict the low heating value fuel turbulent diffusion combustion characteristics.

The hybrid dual-fuel combined cycle concept is a promising technology for increasing the energy utilization of low-grade (solid) fuels. Advantages such as enhanced electrical efficiency, favorable economics, and relative ease of construction and operation have been pointed out by various authors in previous studies. The present investigation aims to assess the performance of natural gas and coal- or biomass-fired hybrid combined cycles, with a gas turbine as topping cycle and a steam boiler as bottoming cycle. A parametric analysis considers the impact of the natural gas/solid fuel energy ratio on the electrical efficiency of various hybrid system configurations. Results show that significant performance improvements (in the order of several percentage points in electrical efficiency) can be achieved by these hybrid configurations when compared to the reference (two independent, single-fuel power plants at the given scales). In large-scale power plants with coal-fired bottoming cycle, efficiencies continuously rise as the share of natural gas fuel is increased up to the cycle integration limits, while an optimum can be seen for the small-scale biomass-fired bottoming cycles (with modest steam parameters) at a certain share of natural gas fuel input.

An economic model was developed to evaluate gas turbine component alternatives for base load combined cycle operation, cyclic duty simple cycle operation, and peaking duty simple cycle operation. Power plant operator value of alternative replacement first stage buckets for a GE Frame 7EA gas turbine is evaluated. The popularity and large installed base of the 7EA has prompted a number of replacement part offerings, in addition to the replacement parts offered by the OEM. A baseline case is established to represent the current bucket repair and replacement situation. Each of the modes of power plant operation is evaluated from both a long-term financial focus and a short-term financial focus. Long-term focus is characterized by a nine-year evaluation period, while short-term focus is based on first year benefit only. Four factors are considered: part price repair price, output increase, and simple cycle efficiency increase. Natural gas and liquid fuels are considered. Two natural gas prices are used; one liquid fuel price is considered. Peak, off-peak, and spot market electricity prices are considered. Two baseline repair price scenarios are evaluated: 50% of new part price and 10% of new part price. The key conclusions can be summarized as: • A reduced-life part with more frequent repair intervals is undesirable, even if the part price is reduced by over 60% and the cooling flow is reduced by 1% W 2 . • A short-life, “throw-away” part with no required repairs can achieve parity with the baseline if the price is reduced by 25% or more. The operator with a short-term focus will not differentiate between a “throw-away” part and a full-life part. • In general, increased part life has less value to the power plant operator than price reduction or cooling flow reduction. • Repair price (assumed to be 50% of part price) is a relatively small factor for operators with a long-term focus, and no factor at all for operators with a short-term focus. A lower baseline repair price (10% of part price) will decrease the attractiveness of a “throw-away” part, moving the parity point to a 40% price reduction. • A 0.7% W 2 reduction in cooling flow has roughly the same first year benefit, at baseline fuel prices, as a 10–15% bucket price reduction, except to the peak duty operator. The peak duty operator finds no benefit to reduced cooling flow unless electricity can be sold at spot market prices.

Technological advances and high cost of ownership have resulted in considerable interest in advanced maintenance techniques. Quantifying fault and consequently availability requires the use of gas turbine and combined cycle models able to undertake appropriate diagnostics and life cycle costing. These are complex areas as they include the simulation of such issues as performance and assessment of degraded gas turbines, life usage and risk analysis. This paper describes how the recent developments in engine diagnostics using advanced techniques like Artificial Neural Networks (ANN) and Genetic Algorithm (GA) based technique have opened new opportunities in the field of engine fault diagnostics. It also discusses the potential of advanced engine diagnostics using such features as ANN and GA in contributing to the management of availability for industrial gas turbines.

At the start of this new century, environmental regulations and free-market economics are becoming the key drivers for the electricity generating industry. Advances in Gas Turbine (GT) technology, allied with integration and refinement of Heat Recovery Steam Generators (HRSG) and Steam Turbine (ST) plant, have made Combined Cycle installations the most efficient of the new power station types. This potential can also be realized, to equal effect, by adding GT’s and HRSG’s to existing conventional steam power plants in a so-called ‘repowering’ process. This paper presents the economical and environmental considerations of retrofitting the steam turbine within repowering schemes. Changing the thermal cycle parameters of the plant, for example by deletion of the feed heating steambleeds or by modified live and reheat steam conditions to suit the combined cycle process, can result in off-design operation of the existing steam turbine. Retrofitting the steam turbine to match the combined cycle unit can significantly increase the overall cycle efficiency compared to repowering without the ST upgrade. The paper illustrates that repowering, including ST retrofitting, when considered as a whole at the project planning stage, has the potential for greater gain by allowing proper plant optimization. Much of the repowering in the past has been carried out without due regard to the benefits of re-matching the steam turbine. Retrospective ST upgrade of such cases can still give benefit to the plant owner, especially when it is realized that most repowering to date has retained an unmodified steam turbine (that first went into operation some decades before). The old equipment will have suffered deterioration due to aging and the steam path will be to an archaic design of poor efficiency. Retrofitting older generation plant with modern leading-edge steam-path technology has the potential for realizing those substantial advances made over the last 20 to 30 years. Some examples, given in the paper, of successfully retrofitted steam turbines applied in repowered plants will show, by specific solution, the optimization of the economics and benefit to the environment of the converted plant as a whole.

This paper is an additional report to the paper by Amano (2001). In this paper, the authors report the additional experimental results of the effect of an ammonia mass fraction at the inlet of the AWM (Ammonia-Water Mixture) vapor generator in the AWM turbine system. The AWM turbine system features the Kalina Cycle technology. The 70KW-experimental facility was built in order to gain knowledge for practical applications. The heat source is the exhaust steam from a back-pressure steam turbine. The AWM turbine system is installed at the bottoming stage of a combined cycle which has a gas turbine, a steam turbine and an AWM turbine for cascade utilization of heat. The authors designed and constructed an experimental facility, the ACGS (the Advanced Co-Generation System), to investigate various energy-saving technologies for a distributed energy supply system in the Advanced Research Institute for Science and Engineering at Waseda University. One of the main targets is a hybrid combined heat and power supply system that uses AWM as its working fluid. The AWM turbine system was developed for the bottoming stage of a “trinary turbine cycle system” which is composed of a gas turbine, a steam turbine and the AWM turbine systems. The experimental results of the ammonia mass fraction to the cycle efficiency are investigated with a range of the ammonia mass fraction between 0.4 [ NH3 kg/kg] to 0.7 [ NH3 kg/kg]. It shows that there are optimal operating conditions depending on the heat source temperature with an ammonia mass fraction of the cycle. The simulation model of the AWM turbine system shows good agreement with the experimental data.

The paper presents a thermo-economic analysis of gas/steam combined cycle. The stated objective is achieved by optimizing thermo-economic parameters for simple combined cycle (large and medium range) and to apply this to economic model of these cycles. The economic parameters evaluated in the present study include discount cash flow rate of return (DCRR) and gross payout period (GPO), two terms commonly employed in engineering economic analysis. DCRR and GPO are calculated for various electric sale and fuel prices. It has been found that maximum value of DCRR and minimum value of GPO are found with large size plant.

Alstom has developed a monitoring and optimization system to offer the power plant an integrated maintenance and diagnosis system. This system is capable of monitoring all Alstom machines and processes in a combined cycle power plant: the gas turbine, steam turbine, generator, HRSG, and cooling system. All data archived in a central database server. Any personal computer networked with the server can display the process data and calculated results. To limit the scope of current paper, only the gas turbine monitoring and diagnostic module is presented. The system concept, configuration, and the environment of gas turbine module as well as capability will be discussed in this paper. The Gas Turbine Module (GTM) provides continuous monitoring of the GT process and continuous displaying of certain calculated results. The GTM provides a tool aimed to help the operator to make decisions, which affect efficiency, reliability and damage control. The monitoring areas include combustion stability (pulsation analysis), exhaust temperature distribution, compressor fouling and surge margin, and thermal performance. Furthermore, the GTM can provide the thermodynamic variables at the gas turbine exhaust for other applications in the combined cycle calculation. The implementation of this module is based on the users’ requirements to optimize the operation, to increase plant reliability and availability, and to optimize equipment performance. The GTM is a PC-based monitoring and diagnostic system. A guiding principal is that the retrofit of the GTM should have minimal impact on the gas turbine control system. This is the reason the system is PC based. A remote connection can be made via network. Users can access and see all real time and historical data by means of a networked computer. The real key success of the GTM is to be able to detect an early component failure and abnormalities during normal plant operation. Therefore, this information can be used for plant management, production forecast, equipment maintenance, and part replacement decision strategy.

Water droplet erosion continues to pose a serious potential threat to the critical path of maintenance outages. Despite advances in techniques and processes to mitigate erosion, combined cycle arrangements still result in an unexpected level of wetness within the steam, which can produce extensive damage to the last stage blade rows. A procedure is discussed that has been used successfully to manage the critical reliability issues that are raised once conditions of water droplet erosion are found. Erosion rate is estimated from (1) empirical models obtained from the literature, (2) for the steam flow conditions specific to the unit, and (3) with stresses obtained from analysis of the damaged blades. Two applications are presented to demonstrate how the erosion rates were used to provide a basis for two very different strategies, both of which were able to avoid the prohibitive cost of extending the immediate outage to obtain and install new replacement rows.

Fifteen municipal electric utilities are jointly studying the feasibility of developing a 500 MW to 1,000 MW coal-fired generation project. The project will combine advanced technologies seeking maximum performance, minimal risk and outstanding environmental acceptability. This paper describes engineering and financial studies comparing coal-firing technology alternatives such as Pulverized Coal (PC), Circulating Fluidized Bed and Integrated Gasifier Combined Cycle, and PC refinements including supercritical steam conditions and innovative use of gas turbine feedwater heating. The paper also examines options to minimize environmental impact. Use of high-efficiency steam plant technologies is found to be an environmental advantage. A prudent combination of sophisticated technologies is found to be cost-effective. Finally, the paper describes the project’s innovative joint development process.

In the past year, Constellation Power Source Generation (CPSG) has commissioned (or is commissioning) four new combined cycle and simple cycle gas turbine plants. Each of these plants involved different equipment, vendors and architect engineers. Acceptance testing was done for these plants in accordance with ASME PTCs 46 and 22 with support from Fossil Consulting Services, Inc. (FCS). The Performance Test Codes provided the framework for the testing done, but considerable work was required to apply the codes in accordance with relevant contracts. Problems in acceptance testing can result in costly delay and retesting. This paper describes the lessons learned in resolving issues and problems that can help others in planning for and executing similar tests. These lessons learned can also help in writing effective contracts between owners, vendors and architect engineers.

Based on field-tested performance and third-party evaluations, Beacon Power has demonstrated that high-energy flywheel systems are a sustainable energy storage option for many electrical applications. Successful power quality implementations range from low-power telecommunications equipment (low-kW for hours) to high-power industrial support (hundreds of kW for seconds). Using this proven technology, Beacon Power has begun development of a modular, high-energy system to deliver robust and responsive megawatt output levels — for seconds, minutes and even hours. This flywheel energy matrix would be ideal for grid stabilization, spinning reserves, renewable power, and distributed resource applications. For example, a system such as this would have sufficient energy to provide the minutes needed for ride-through capability to start smaller gas turbine-powered generators. This paper describes thc tecchnical feasibility of combining thc best features of flywheel energy storage with standard high-power electronics for energy storage and delivery. Two system-level configuration options are discussed: 1) Fixed installations, comprising a matrix of flywheels installed in a building with the Power Conversion System (PCS); and, 2) Deployable, portable equipment, based on a system-modular approach comprising an array of flywheels and PCS packaged in a standard shipping container to be easily dispatched for grid stabilization or load support. The technical discussion includes a building block-level component description of the flywheel and its motor/generator drive, electrical ratings, mechanical ratings and more. At a system level, an overview of component interconnection is provided, including links to the PCS. In addition, footprint and weight values are illustrated for both proposed system configuration options. This paper also includes a more detailed examination of ways in which this innovative energy storage solution can be economically used in electric supply systems. The flywheel’s deep discharge and resilient, high-power cyclic capability, combined with a long design life, make it an ideal solution for voltage and frequency stabilization as well as an attractive, passive alternative for spinning reserves. The paper focuses and expands upon the strengths and limitations of today’s flywheel technologies. Finally, the effects and impact of the ways that energy is produced, delivered, and consumed are summarized.

This paper describes the modeling of a 27 MW combined cycle cogeneration plant with 10,000 tons chilled water central cooling facility. The cogeneration plant is designed to provide heating, cooling and electricity from a single fuel source viz., natural gas, though the gas turbines do have an inbuilt dual fuel combustion system. The topping cycle of the combined cycle cogeneration plant consists of two gas turbines each producing 11 MW of electric power at full load. The energy of the exhaust gases from these gas turbines is then utilized to generate steam in two heat recovery steam generators. The heat recovery steam generators are duct fired using natural gas to meet the peak steam load. In the bottoming part of the combined cycle, the steam from the heat recovery steam generators is expanded in a backpressure steam turbine to supply steam to the campus at about 963 kPa, generating an additional 5.5 MW of electric power in this process. There is no condenser wherein the campus acts as a sink for the steam. The central cooling facility is designed to supply 10,000 tons of chilled water out of which 3800 tons is supplied by two steam driven centrifugal chillers, which utilize a part of the steam supplied to the campus and the remaining by the centrifugal electric chillers. The combined cycle cogeneration plant along with the central chilled watercooling facility is modeled in a commercially available flexible cogeneration software package. The model is built based on the design data available from design manuals of gas turbines, heat recovery steam generators, backpressure steam turbine and centrifugal chillers. A parametric study is also done on the model to study the effect of different parameters like fuel flow rate, temperature etc on the output of the turbine and efficiency of the plant. Modeling of the inlet air-cooling of the gas turbine using an absorption chiller and electric chiller is also presented. Finally the paper discusses these results.

This paper reports on the development requirements of gas/steam combined cycle with an aim to achieve plant efficiency greater than 62% through various development possibilities in gas turbine and steam turbine cycle by taking a reference combined cycle configuration (MS9001H gas turbine and three pressure heat recovery steam generator with reheat). The innovative development possibilities include the advanced inlet design to reduce pressure loss, the increase in turbine inlet temperature, use of advanced turbine blade material, increased component efficiency, improved turbine cooling technologies along with better cooling medium, incorporating intercooling, reheat and regeneration either separately or in combination with simple gas turbine cycle using higher compressor pressure ratio, better utilization of heat recovery steam generator, minimum stack temperature, single shaft system configuration, etc. Based on the quantification of each development item, if incorporated in reference cycle, it has been estimated that the combined cycle as the potential to achieve the plant efficiency in excess of 63%.

Lincoln Electric System, the public power utility of Lincoln, Nebraska, will complete a multiple LM6000 gas turbine station project at the end of 2003 that features Selective Catalytic Reduction (SCR) for both combined cycle as well as simple cycle. Furthermore, the facility will be capable of meeting ultra low emissions levels of nitrogen oxides when firing both natural gas and Number 2 fuel oil. This discussion explores the selection and implementation of these emission control systems from procurement through first fire. Burns and McDonnell, of Kansas City, Missouri, led the design effort of this green field site and co-authors with members of the utility.

It is said that gas turbine generating plants on simple cycle reduce the power output by 3% in variation with 1% increase of ambient temperature change. When maintaining maximum cycle temperature, i.e., turbine inlet temperature (T4), the reduction of temperature ratio cannot be avoided by increasing minimum cycle temperature, i.e., ambient temperature (T2). Accordingly, the useful power output must be reduced and the thermal energy would be emitted into the atmosphere. The widely used combined cycle plant is an idea to recover the not-used thermal energy into the power, and it is still losing power by 2% in variation with 1% of the ambient temperature. In order to recover effectively such waste thermal energy into the power output, many ideas are adopted to mainly aim the thermal efficiency exceeding 60%, like “Steam-Cooled Combined Cycle”, “Kalina Cycle” etc. It was confirmed that the water/steam-injected WI/GAS3D GT version of modified LM6000 could produce 106 MW with 56% thermal efficiency at ISO conditions *6 , and it is demonstrated, this time, that the power curve of the plant in variation with ambient temperature is very flat, comparing with those of conventional GT plants. It might be recommended to establish advantageous cycle plants using the more advanced gas turbines derived from like GE90, PW4000, and Trent800, in order to get exceeding 60% thermal efficiency in hot climate conditions, and it would be expected that such technology application might contribute to execute the worldwide COP3 agreement by saving the fossil fuel usage, resulting in minimal CO2 emissions.

This paper presents a comparative study of first and second law thermodynamic analysis of combined and recuperated and non-recuperated steam injected gas turbine cycles. The analysis has been carried out by developing a computer code, which is based on the modeling of various elements of these cycles. The gas turbine chosen for the analysis is MS9001H developed recently by GE and the steam cycle is having a triple-pressure heat recovery steam generator with reheat. It has been observed that the combined cycle is superior to the steam injected cycle, however, the gap narrows down with increasing compressor pressure ratio and high value of turbine inlet temperature. The detailed exergy losses have been presented in various elements of combined and steam injected cycles.